Range Announces Third Quarter 2013 Results

  Range Announces Third Quarter 2013 Results

Business Wire

FORT WORTH, Texas -- October 29, 2013

RANGE RESOURCES CORPORATION (NYSE: RRC) today announced its third quarter 2013
financial results.

Third Quarter Highlights –

  *Record production of 960 Mmcfe per day, an increase of 21% over the
    prior-year quarter.
  *Adjusted cash flow was $244 million, an increase of 29% as compared to the
    prior-year quarter.
  *Unit costs were reduced 12% versus the prior-year quarter.
  *Basin leading liquids-rich wells drilled in Pennsylvania continue to
    provide impressive results.
  *Approximately 540,000 net acres of Range’s leasehold is in southwest
    Pennsylvania where the largest estimated gas in place (GIP) occurs when
    combining all three shale horizons.
  *Range’s southwest and northeast Marcellus natural gas price realizations
    were $0.41 and $0.56 higher, respectively, than local pricing indices.
  *Mariner West Project, exporting ethane to Sarnia, Canada, is expected to
    be fully operational in November.
  *When all three ethane solutions are fully operational, based on today’s
    prices, Range’s average price for ethane would equate to a natural gas
    price of $4.13, net of transportation cost without considering the
    expected benefit of up to 8% additional propane recovery which could add a
    net $0.40 to $0.50 to an equivalent natural gas price.

Commenting on the announcement, Jeff Ventura, Range’s President and CEO, said,
“Range continued to make significant progress during the third quarter, with
record production results, lower unit costs, and materially higher cash flow.
Our balance sheet, liquidity and cash flow growth positions us well to
continue growing production 20% to 25% for many years. With the progress made
during the first three quarters of 2013, we are focused on achieving the
higher end of our production growth range for 2013 even with the sale of our
New Mexico properties. The first delivery of ethane into the Mariner West
pipeline to Sarnia, Canada commenced in July with intermittent deliveries and
the project is expected to be fully operational in November. Once fully
operational, Mariner West will allow us to continue our planned growth without
concern for pipeline quality requirements for our residue gas. Our growth is
led by our approximate one million acre leasehold position in Pennsylvania
which essentially doubles when stacked pay reservoirs across most of our
acreage in the Basin are considered. This acreage position is anchored by the
Marcellus, the most prolific gas reservoir in North America. Based on the
estimated gas in place (GIP) maps released by Range today, our southwest
Pennsylvania acreage is strategically located at the nexus where the largest
estimated gas in place exists when considering all three shale horizons. Range
believes that this area also encompasses the core of the super-rich and wet
areas of both the Marcellus and the Upper Devonian shales. We believe that our
expected 20% to 25% production growth for many years, coupled with the high
returns, low cost and low reinvestment risk will drive substantial per share
value for our shareholders for years to come.”

Financial Discussion

(Except for generally accepted accounting principles (“GAAP”) reported
amounts, specific expense categories exclude non-cash impairments, unrealized
mark-to-market on derivatives, non-cash stock compensation and other items
shown separately on the attached tables.)

GAAP revenues for the third quarter of 2013 totaled $442 million (a 47%
increase as compared to third quarter 2012), GAAP net cash provided from
operating activities including changes in working capital was $223 million (a
25% increase as compared to third quarter 2012) and GAAP earnings increased by
136% to $19 million ($0.12 per diluted share) versus a loss of $54 million
($0.34 per diluted share loss) in the third quarter 2012.

Non-GAAP revenues for third quarter 2013 totaled $433 million (a 21% increase
as compared to third quarter 2012), cash flow from operations before changes
in working capital, a non-GAAP measure, reached $244 million ($1.51 per
diluted share, a 28% increase as compared to third quarter 2012). Adjusted net
income, a non-GAAP measure, was $57 million ($0.35 per diluted share, a 75%
increase as compared to third quarter 2012).

Several non-cash or non-recurring items impacted third quarter results. A
$33.4 million mark-to-market commodity hedge loss was recognized for GAAP
reporting along with a $6 million gain on sale of assets. An unproved property
impairment expense of $11.7 million was recorded along with a $7 million
proved property impairment on minor Gulf coast properties. A net expense of
$3.7 million was incurred for blending the Company’s rich residue gas to meet
pipeline quality requirements. A $13.2 million non-cash stock compensation
expense was recorded while a reduction in deferred compensation expense of
$2.2 million was recognized with the decrease in the common stock price
between quarters.

Reviewing the Company’s six major expense categories, total unit costs
decreased by $0.47 per mcfe or 12% compared to the prior-year quarter led by
decreases in interest expense (-18%), general and administrative expense
(-17%), direct operating expense (-15%), depreciation, depletion and
amortization expense (-12%), and transportation, gathering and compression
(-3%). Production and ad valorem tax expense rose 8% due to higher commodity
prices.

As previously reported, third quarter production volumes reached a record
high, averaging 960 Mmcfe per day, a 21% increase over the prior-year quarter.
Year-over-year oil and condensate production increased 43%, natural gas
liquids (“NGL”) production rose 28%, while natural gas production increased
19%. Adjusting for the sale of the New Mexico properties which closed on April
1, 2013 comprising production of approximately 18 Mmcfe per day at the time of
sale, third quarter production would have increased 24% over the prior-year
quarter with oil and condensate production increasing 58%, NGL production
increasing 29% and natural gas production increasing 21%. The record
production was driven by the continued success of the Company’s drilling
program primarily in the Marcellus Shale. Realized prices, after adjustment
for all cash-settled hedges, averaged $4.80 per mcfe, a 2% decrease from the
prior-year period. Production and realized prices by each commodity for the
third quarter were: natural gas – 739 Mmcf per day ($3.88 per mcf), NGLs –
25,678 barrels per day ($31.08 per barrel) and crude oil and condensate –
11,065 barrels per day ($85.46 per barrel).

See “Non-GAAP Financial Measures” for a definition of each of the non-GAAP
financial measures discussed above and tables that reconcile each non-GAAP
measure to its most directly comparable GAAP financial measure which are
included in this release and on our website.

Capital Expenditures

Third quarter drilling expenditures of $258 million funded the drilling of 46
(45 net) wells and the completion of previously drilled wells. A 100% drilling
success rate was achieved. In addition, during the third quarter, $39 million
was expended on acreage purchases, $20 million on gas gathering systems and
$20 million on exploration expense. The Company remains on track with its 2013
capital expenditure budget of approximately $1.3 billion.

Operational Discussion

Marcellus Shale Marketing and Transportation Update –

Currently, Range has contracts in place for approximately 1.0 Bcf per day of
firm capacity increasing to 1.5 Bcf per day by 2015 at an average cost of
$0.23 per Mmbtu. The term of these contracts is generally for 10 years, the
majority of which are renewable at the expiration date at the option of Range.
Importantly, the majority of Range’s Marcellus activity is located in
southwest Pennsylvania where six of the largest pipelines in Appalachia are
located and pass through. This significant amount of existing infrastructure
has allowed Range to secure firm transportation at rates of approximately
$0.20 to $0.25 per Mmbtu. Range expects that future transportation capacity
will be added at similar rates utilizing existing infrastructure. Range’s
objective is to layer in additional firm commitments that match the Company’s
increasing production volumes. To this end, Range has already contracted for
an additional 200 Mmcf per day of capacity for 2017. The Company is also in
discussions for additional firm capacity on several large takeaway systems.
These future capacity expansions, to multiple markets outside the Appalachian
region, will support our growth while maximizing net realized natural gas
prices.

In addition to the Company’s own firm capacity, Range utilizes firm sales
arrangements with buyers who have their own firm transportation. For 2013,
Range expects its firm sales contracts covering Marcellus gas production will
average approximately 300 Mmcf per day. These contracts generally have terms
of 12 to 24 months. As with firm transportation contracts, Range expects to
extend and add to these firm sales contracts as production grows. Range plans
to continue using a strategy whereby approximately 60% of its Marcellus
natural gas volumes are sold under the Company’s own firm transportation and
the remainder will be sold under firm sales arrangements where the purchaser
owns firm transportation. This strategy, combined with the Company’s access to
multiple markets outside of Appalachia, allows Range the flexibility of
flowing gas to multiple markets at reasonable costs and maximizing its price
realizations rather than being limited solely to the local markets.

Third quarter 2013 Marcellus realizations were a reflection of this strategy
as the Company received prices greater than the local markets. Range’s
realized average natural gas price for all its Marcellus natural gas
production was $0.06 below the NYMEX Henry Hub benchmark price for the
quarter. By region, Range’s realized prices were $0.41 better than the average
of the TCO, DTI and TETCO M2 index prices in southwest Pennsylvania and were
$0.56 better than the average of the Leidy/Transco index price for the third
quarter in northeast Pennsylvania.

Mariner West Project-

Mariner West is expected to be fully operational in November. Pipeline testing
and line fill has been ongoing since July. The project has several benefits to
Range, including:

1. Removal of ethane from the gas stream, allowing Range to meet pipeline
specifications and continue to grow southwest Pennsylvania wet gas volumes.

2. Current base pricing FOB at the Houston, Pennsylvania plant, is attractive.

3. Ethane extraction results in up to an additional 8% increase in propane
volumes which carry a more attractive net back price.

Range’s Marketing Plan-

Range is the largest producer of wet gas in the Appalachian Basin, with the
most comprehensive and diversified plan to move our growing volumes of gas,
NGLs and condensate. Our existing contracts and commitments are intended to
ensure we can move our products to new and growing markets at prices greater
than the local markets. Our innovative portfolio of ethane marketing
arrangements, the result of many years of negotiation and planning,
demonstrate this. The three contracts include two long-term sales contracts
providing export of ethane to two international destinations, Canada and
Europe, plus a transportation agreement to the Gulf Coast. We believe that if
these three marketing arrangements were fully operational today, based on
today’s prices, our average price for ethane would equate to a natural gas
price of $4.13, net of transportation cost without considering the expected
benefit of up to 8% additional propane recovery, which at today’s prices could
add a net $0.40 to $0.50 to an equivalent natural gas price. In addition,
propane exports from the Marcus Hook facility in Philadelphia have started,
with additional sales expected both locally and internationally, when the
Mariner East project becomes operational in 2014.

Marcellus Shale–

Marcellus production for the third quarter averaged approximately 900 (756
net) Mmcfe net per day. Marcellus production for the first nine months of 2013
averaged approximately 855 (718 net) Mmcfe net per day, which represents a 40%
increase on a year to date comparison to 2012.

Range has updated its investor presentation with gas in place (GIP) maps for
the Appalachian Basin reflecting the individual and combined Marcellus, Upper
Devonian and Utica/Point Pleasant Shales. Please see www.rangeresources.com
under the Investor Relations tab, “Presentations and Webcasts” area, for the
presentation entitled, “Company Presentation – October 29, 2013.” The maps
reflect our view that the estimated greatest GIP accumulation in these
respective shales is located in the southwestern portion of Pennsylvania. This
mapping of GIP has been a key driver for Range concentrating its acreage
position in this area to take advantage of the multiple stacked horizons,
complemented by the core liquid rich areas of the Marcellus and Upper Devonian
shales.

Southern Marcellus Shale Division –

Range estimates that its acreage in southwest Pennsylvania is amongst the core
of the Appalachian Basin based on well results and gas in place estimates.
During the third quarter, the division brought online 26 Marcellus wells in
this area, with 24 wells in the super-rich area, and two wells in the dry gas
area.

In the super-rich area of southwest Pennsylvania the division brought online
24 (23 net) wells in the third quarter. The initial 24-hour production rates
of these super-rich wells averaged 2,657 (2,122 net) boe per day with 66%
liquids assuming 80% ethane extraction. All of the wells in the quarter were
completed with reduced cluster spacing. The average lateral length for the
wells was 4,030 feet and they averaged 21 frac stages per lateral. The higher
initial production rates and higher expected recoveries are a result of
improved targeting and completion techniques that are now being applied by
Range across all areas of the play. The performance of the 17 super-rich
wells, that were announced earlier this year, continues to impress. Now having
been on line 240 days, these wells are 43% above the 1.32 Mmboe type curve.
(The Company has included in its current corporate presentation an updated
zero time plot covering these super-rich wells.)

Range’s best well in the super-rich area, announced last quarter, had an
initial 24-hour production rate of 5,720 boe per day with 63% liquids assuming
80% ethane extraction. The well produced an average 30-day rate of 2,700 boe
per day with 61% liquids, and an average 60-day rate of 2,121 boe per day with
60% liquids assuming 80% ethane extraction. Among liquids rich wells, with
initial production of 60% liquids or greater, Range believes that it has
drilled five of the top ten producing wells in the Appalachian Basin.
Normalizing results, on a per 1,000 lateral foot basis, Range has drilled
eight of the top ten liquids rich producing wells.

At quarter-end the division’s backlog of wells waiting on pipeline connection
decreased to 11 wells. Range expects to turn to sales a total of 125 wells in
the southern Marcellus during 2013. Range continues to minimize the number of
wells drilled but waiting on pipeline connection allowing for better
utilization of capital spent.

Northern Marcellus Shale Division –

In northeast Pennsylvania, Range brought online 10 wells in the third quarter
including a step-out well in Lycoming County that had a 24-hour initial
production rate of 22.9 (19.7 net) Mmcf per day. The 30-day average rate for
the same well was 15 (12.9) Mmcf per day. In 60 days the well has produced
over 750 Mmcf. Two more wells on the same pad were recently turned to sales
under constrained conditions at a combined rate of 42 (36.1 net) Mmcf per day.
The three wells on the pad have an average lateral length of about 5,000 feet
and 23 frac stages. The division’s backlog of wells waiting on pipeline
connection declined to 13 at quarter-end. Range anticipates drilling another
four wells during the remainder of 2013 and turning an additional 9 wells to
sales.

At the end of the third quarter, in the Bradford County area operated by
Talisman, there were a total of 38 (11.2 net) wells producing and 31 (9.1 net)
wells waiting on completion or pipeline connection.

Midcontinent Division –

During the third quarter, the Midcontinent division continued to focus on
Range’s horizontal Mississippian acreage along the Nemaha Ridge. Initially,
activity has been concentrated across the southern portion of the Company’s
acreage position. In October, Range completed a 12 mile northern step-out well
that had an initial 7-day production of over 300 barrels of oil per day and an
average 30-day rate of 330 boe per day with 94% liquids (85% oil and 9% NGLs).
The division tested completions with larger frac stimulations on four wells
that averaged production rates 45% above the 600 Mboe type curve for the first
65 days. Results from wells completed with the larger fracs continue to
significantly exceed results seen from wells drilled in the early part of 2013
that were completed with smaller fracs. A total of 7 (6.8 net) wells were
turned to sales during the quarter with average lateral lengths of 3,742 feet
with 21 frac stages. The initial production on these wells averaged 622 (493
net) boe per day with 75% liquids and is the highest average for any quarter
to date. Despite the larger fracs, Range has been able to drill and complete
the wells at the same cost of $3.2 million. Range anticipates bringing online
four additional horizontal Mississippian wells with larger frac stimulations
during the fourth quarter.

Range also turned to sales two St. Louis wells during the quarter with a
24-hour initial combined production rate of 20.5 (13.4 net) Mmcfe per day with
28% liquids. The Company expects to drill another two wells in that area
during the fourth quarter.

Permian Division –

Range’s Permian division turned to sales six additional vertical Wolfberry
wells in the third quarter of 2013. Average 24-hour initial production rates
were 324 (243 net) boe per day with 77% liquids. During the remainder of the
year, Range has drilled and is currently completing both a Cline and a
Wolfcamp horizontal well with 7,000 foot laterals.

Southern Appalachia Division –

The Southern Appalachia division continued development of multi-pay horizons
on its 350,000 (250,000 net) acre position in Virginia. Range owns the fee
minerals on 216,000 acres of this position and receives the added economic
benefit of the royalty for wells drilled on this acreage. Range drilled two
horizontal Huron Shale wells, and turned to sales five wells during the third
quarter. The Company expects to turn to sales another three wells during the
remainder of 2013.

Guidance

Production Guidance:

Production growth for 2013 is now targeted to the higher end of our original
20% to 25% year-over-year guidance. Production for the fourth quarter of 2013
is expected to average approximately 1.0 Bcfe per day with 25% liquids.

Guidance for 2013 Activity:

Under the current plan, Range expects to turn to sales approximately 196 net
wells in the Marcellus and Horizontal Mississippian during 2013, as shown
below. A number of the wells expected to be turned to sales in the fourth
quarter are expected to occur just before year-end, and therefore will not
have a material impact on production for the quarter.

                                                     
                     Year to Date     Expected           Total Planned
                     Wells to Sales   Remaining Wells    Wells to Sales
                     in 2013          to Sales in 2013   in 2013
Super-Rich area      63               18                 81
Wet area             15               10                 25
Dry area (NE & SW)   40               11                 51
Total Marcellus      118              39                 157
Hz. Mississippian    35               4                  39
Total                153              43                 196

                                                    
Expense per mcfe 4Q 2013 Guidance:
                                                       
  Direct operating expense:                            $0.34 - $0.36 per mcfe
  Transportation, gathering and compression expense:   $0.77 - $0.79 per mcfe
  Production tax expense:                              $0.14 - $0.15 per mcfe
  Exploration expense:                                 $16 - $17 million
  Unproved property impairment expense:                $14 - $16 million
  G&A expense:                                         $0.39 - $0.41 per mcfe
  Interest expense:                                    $0.49 - $0.50 per mcfe
  DD&A expense:                                        $1.46 - $1.48 per mcfe

                                                              
Total Corporate Differential Pricing History (a)
                                                                      
               2Q 2012    3Q 2012    4Q 2012    1Q 2013    2Q 2013    3Q 2013
  Natural      ($0.13 )   ($0.03 )   $ 0.18     $ 0.15     $ 0.04     ($0.17 )
  Gas
  NGL (% of    39     %   33     %     43   %     38   %     33   %   31     %
  WTI NYMEX)
  Oil (% of    91     %   90     %     89   %     90   %     89   %   87     %
  WTI NYMEX)

(a) Differentials based on pre-hedge pricing, excluding transportation,
gathering and compression expense.

Hedging Status

Range hedges portions of its expected future production volumes to increase
the predictability of cash flow and to help maintain a strong, flexible
financial position. Range currently has over 75% of its expected remaining
2013 natural gas production hedged at a weighted average floor price of $4.20
per mcf. Similarly, Range has hedged more than 80% of its projected remaining
crude oil production at a floor price of $94.90 and more than 50% of its
composite NGL production near current market prices. Please see Range’s
detailed hedging schedule posted at the end of the financial tables below and
on its website at www.rangeresources.com.

Effective March 1, 2013, Range elected to discontinue hedge accounting for
derivative contracts and moved to mark-to-market accounting for its derivative
contracts. The mark-to-market accounting treatment may create fluctuations in
earnings as commodity prices change both positively and negatively, however,
such mark-to-market adjustments have no cash flow impact. The impact to cash
flow will occur as the underlying contracts are settled. As of October 1,
2013, the Company expects to reclassify into earnings $22.1 million of
unrealized net gains frozen in the first quarter with discontinuance of hedge
accounting in the remaining three months of 2013 and $10.2 million of
unrealized net gains in 2014.

Conference Call Information

A conference call to review the financial results is scheduled on Wednesday,
October 30 at 09:00 a.m. ET. To participate in the call, please dial
877-407-0778 and ask for the Range Resources third quarter 2013 financial
results conference call. A replay of the call will be available through
November 30, 2013. To access the phone replay dial 877-660-6853. The
conference ID is 100298.

A simultaneous webcast of the call may be accessed over the Internet at
http://www.rangeresources.com. The webcast will be archived for replay on the
Company's website until November 30, 2013.

Non-GAAP Financial Measures:

Adjusted net income comparable to analysts’ estimates as set forth in this
release represents income or loss from operations before income taxes adjusted
for certain non-cash items (detailed below and in the accompanying table) less
income taxes. We believe adjusted net income comparable to analysts’ estimates
is calculated on the same basis as analysts’ estimates and that many investors
use this published research in making investment decisions useful in
evaluating operational trends of the Company and its performance relative to
other oil and gas producing companies. Diluted earnings per share (adjusted)
as set forth in this release represents adjusted net income comparable to
analysts’ estimates on a diluted per share basis. A table is included which
reconciles income or loss from operations to adjusted net income comparable to
analysts’ estimates and diluted earnings per share (adjusted). On its website,
the Company provides additional comparative information on prior periods along
with non-GAAP revenue disclosures.

Third quarter 2013 earnings included a loss of $33.4 million for the non-cash
unrealized mark-to-market decrease in value of the Company’s derivatives,
unproved property impairment expense of $11.7 million, a $2.2 million gain
recorded for the mark-to-market valuation in the deferred compensation plan,
$13.2 million of non-cash stock compensation expenses, and a $7 million proved
property impairment on some minor properties on the Gulf coast. A net expense
of $3.7 million was also incurred for blending the Company’s rich residue gas
to meet pipeline quality requirements. Excluding these and other items, net
income would have been $57.0 million or $0.35 per diluted share. Excluding
similar non-cash items from the prior-year quarter, net income would have been
$32.0 million or $0.20 per diluted share. By excluding these non-cash items
from our reported earnings, we believe we present our earnings in a manner
consistent with the presentation used by analysts in their projection of the
Company’s earnings. (See the reconciliation of non-GAAP earnings in the
accompanying table.)

Cash flow from operations before changes in working capital as defined in this
release represents net cash provided by operations before changes in working
capital and exploration expense adjusted for certain non-cash compensation
items. Cash flow from operations before changes in working capital is widely
accepted by the investment community as a financial indicator of an oil and
gas company’s ability to generate cash to internally fund exploration and
development activities and to service debt. Cash flow from operations before
changes in working capital is also useful because it is widely used by
professional research analysts in valuing, comparing, rating and providing
investment recommendations of companies in the oil and gas exploration and
production industry. In turn, many investors use this published research in
making investment decisions. Cash flow from operations before changes in
working capital is not a measure of financial performance under GAAP and
should not be considered as an alternative to cash flows from operations,
investing, or financing activities as an indicator of cash flows, or as a
measure of liquidity. A table is included which reconciles “Net cash provided
by operations” to “Cash flow from operations before changes in working
capital” as used in this release. On its website, the Company provides
additional comparative information on prior periods for cash flow, cash
margins and non-GAAP earnings as used in this release.

The cash prices realized for oil and natural gas production including the
amounts realized on cash-settled derivatives and net of transportation,
gathering and compression expense is a critical component in the Company’s
performance tracked by investors and professional research analysts in
valuing, comparing, rating and providing investment recommendations and
forecasts of companies in the oil and gas exploration and production industry.
In turn, many investors use this published research in making investment
decisions. Due to the GAAP disclosures of various derivative transactions and
third party transportation, gathering and compression expense, such
information is now reported in various lines of the income statement. The
Company believes that it is important to furnish a table reflecting the
details of the various components of each income statement line to better
inform the reader of the details of each amount and provide a summary of the
realized cash-settled amounts and third party transportation, gathering and
compression expense which historically were reported as natural gas, NGLs and
oil sales. This information will serve to bridge the gap between various
readers’ understanding and fully disclose the information needed.

The Company discloses in this release the detailed components of many of the
single line items shown in the unaudited GAAP financial statements included in
the Company’s Quarterly Report on Form 10-Q. The Company believes that it is
important to furnish this detail of the various components comprising each
line of the Statements of Operations to better inform the reader of the
details of each amount, the changes between periods and the effect on its
financial results.

Hedging and Derivatives

As discussed in this news release, Range has reclassified within total
revenues its financial reporting of the cash settlement of its commodity
derivatives. Under this presentation, those hedges considered “effective”
under ASC 815 are included in “Natural gas, NGLs and oil sales” when settled.
For undesignated hedges and those hedges designated to regions where the
historical correlation between NYMEX and regional prices is “non-highly
effective” or is “volumetric ineffective” due to sale of the underlying
reserves, they are deemed to be “derivatives” and the cash settlements are
included in a separate line item shown as “Derivative fair value income
(loss)” in the consolidated statements of operations included in the Company’s
Form 10-Q along with the change in mark-to-market valuations of such
unrealized derivatives. Effective March 1, 2013 the Company de-designated all
commodity contracts and elected to discontinue hedge accounting prospectively.
The Company has provided additional information regarding natural gas, NGLs
and oil sales in a supplemental table included with this release, which would
correspond to amounts shown by analysts for natural gas, NGLs and oil sales
realized, including cash-settled derivatives.

RANGE RESOURCES CORPORATION (NYSE: RRC) is a leading independent oil and
natural gas producer with operations focused in Appalachia and the southwest
region of the United States. The Company pursues an organic growth strategy
targeting high return, low-cost projects within its large inventory of low
risk, development drilling opportunities. The Company is headquartered in Fort
Worth, Texas. More information about Range can be found at
http://www.rangeresources.com/ and http://www.myrangeresources.com/.

All statements, except for statements of historical fact, made in this release
regarding activities, events or developments the Company expects, believes or
anticipates will or may occur in the future, such as those regarding future
liquidity, production growth, completion of ethane projects, resolution of
pipeline quality requirements, estimated gas in place, future rates of return,
future low costs, low reinvestment risk, earnings and per-share value, capital
spending plans, firm capacity contract renewals, future transportation
capacity rates, continued utilization of existing infrastructure, gas
marketability, firm sales contract renewals, maximized realized natural gas
prices, acreage quality, access to multiple gas markets, expected drilling and
development plans, improved capital efficiency, future financial position and
future guidance information are forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. These statements are based on assumptions and estimates
that management believes are reasonable based on currently available
information; however, management's assumptions and Range's future performance
are subject to a wide range of business risks and uncertainties and there is
no assurance that these goals and projections can or will be met. Any number
of factors could cause actual results to differ materially from those in the
forward-looking statements, including, but not limited to, the volatility of
oil and gas prices, the results of our hedging transactions, the costs and
results of actual drilling and operations, the timing of production,
mechanical and other inherent risks associated with oil and gas production,
weather, the availability of drilling equipment, changes in interest rates,
litigation, uncertainties about reserve estimates, environmental risks and
regulatory changes. Range undertakes no obligation to publicly update or
revise any forward-looking statements. Further information on risks and
uncertainties is available in Range's filings with the Securities and Exchange
Commission ("SEC"), which are incorporated by reference.

The SEC permits oil and gas companies, in filings made with the SEC, to
disclose proved reserves, which are estimates that geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions as well
as the option to disclose probable and possible reserves. Range has elected
not to disclose the Company’s probable and possible reserves in its filings
with the SEC. Range uses certain broader terms such as “resource potential,”
or “unproved resource potential” or “upside” or other descriptions of volumes
of resources potentially recoverable through additional drilling or recovery
techniques that may include probable and possible reserves as defined by the
SEC's guidelines. Range has not attempted to distinguish probable and possible
reserves from these broader classifications. The SEC’s rules prohibit us from
including in filings with the SEC these broader classifications of reserves.
These estimates are by their nature more speculative than estimates of proved,
probable and possible reserves and accordingly are subject to substantially
greater risk of being actually realized. Unproved resource potential refers to
Range's internal estimates of hydrocarbon quantities that may be potentially
discovered through exploratory drilling or recovered with additional drilling
or recovery techniques and have not been reviewed by independent engineers.
Unproved resource potential and gas in place do not constitute reserves within
the meaning of the Society of Petroleum Engineer's Petroleum Resource
Management System and does not include proved reserves. Area wide unproven
resource potential and gas in place has not been fully risked by Range's
management. “Gas in place” is merely an indication of the size of a
hydrocarbon reservoir and is not an indication of reserves or the quantity of
natural gas that is likely to be produced. You should not assume that
estimates of gas in place are comparable to proved reserves or representative
of estimates of future production from our properties. It is not possible to
measure gas in place in an exact way, and estimating gas in place is
inherently uncertain. Gas in place has been estimated based on subjective
analysis of geological and other relevant data applicable to our properties,
including assumptions regarding area, thickness, porosity and saturation.
Changes in these factors or inaccuracies in our assumptions could materially
alter the estimates of gas in place. “EUR,” or estimated ultimate recovery,
refers to our management’s estimates of hydrocarbon quantities that may be
recovered from a well completed as a producer in the area. These quantities
may not necessarily constitute or represent reserves within the meaning of the
Society of Petroleum Engineer’s Petroleum Resource Management System or the
SEC’s oil and natural gas disclosure rules. Actual quantities that may be
recovered from Range's interests could differ substantially. Factors affecting
ultimate recovery include the scope of Range's drilling program, which will be
directly affected by the availability of capital, drilling and production
costs, commodity prices, availability of drilling services and equipment,
drilling results, lease expirations, transportation constraints, regulatory
approvals, field spacing rules, recoveries of gas in place, length of
horizontal laterals, actual drilling results, including geological and
mechanical factors affecting recovery rates and other factors. Actual
quantities that may be recovered from Range’s interests could differ
substantially from estimates disclosed. Estimates of resource potential may
change significantly as development of our resource plays provides additional
data. Investors are urged to consider closely the disclosure in our most
recent Annual Report on Form 10-K, available from our website at
www.rangeresources.com or by written request to 100 Throckmorton Street, Suite
1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K by calling
the SEC at 1-800-SEC-0330.

In addition, our production forecasts and expectations for future periods are
dependent upon many assumptions, including estimates of production decline
rates from existing wells and the undertaking and outcome of future drilling
activity, which may be affected by significant commodity price declines or
drilling cost increases. Investors are urged to consider closely the
disclosure in our most recent Annual Report on Form 10-K, available from our
website at www.rangeresources.com or by written request to 100 Throckmorton
Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form
10-K by calling the SEC at 1-800-SEC-0330.

                                                                                 


RANGE RESOURCES CORPORATION
                                                                                        
STATEMENTS OF
OPERATIONS
Based on GAAP
reported earnings
with additional
details of items
included in each
line in Form 10-Q
(Unaudited, in
thousands, except
per share data)
                   Three Months Ended September 30,    Nine Months Ended September 30,
                     2013        2012      %       2013          2012        %   
Revenues and
other income:
  Natural gas,
  NGLs and oil      $ 431,214     $ 337,040             $ 1,267,131     $ 953,006
  sales (a)
  Realized (loss)
  gain on             (6,951  )     17,625                (28,335   )     21,994
  settlement (a)
  (c)
  Change in fair
  value of
  derivatives
  that did not
  qualify or          (34,219 )     (53,646 )
  were not
  designated for                                          28,350          30,075
  hedge
  accounting (c)
  Hedge
  ineffectiveness     815           (4,707  )             (2,485    )     (5,061    )
  (loss) gain (c)
  Gain (loss) on      6,008         949                   89,129          (12,704   )
  sale of assets
  Brokered
  natural gas,        9,213         3,449                 40,737          12,130
  marketing and
  other
  Brokered
  natural gas -       36,278        -                     40,216          -
  blending (d)
  Equity method       268           (1,012  )             541             (195      )
  investment (d)
  Other (d)          (588    )    82                  (651      )    421       
  Total revenues
  and other          442,038     299,780    47  %    1,434,633     999,666      44  %
  income
Costs and
expenses:
  Direct              30,208        29,030                91,675          84,044
  operating
  Direct
  operating –
  non-cash stock      699           598                   2,056           1,647
  compensation
  (b)
  Transportation,
  gathering and       60,958        51,600                189,422         137,164
  compression
  Production and
  ad valorem          11,454        8,819                 33,950          32,532
  taxes
  Pennsylvania
  impact fee -        -             -                     -               24,707
  prior year
  Brokered
  natural gas and     10,588        4,435                 44,769          14,127
  marketing
  Brokered
  natural gas and
  marketing –
  non-cash stock-
  based
  compensation        531           452                   1,310           1,313
  (b)
  Brokered
  natural gas and     39,998        -                     44,015          -
  marketing –
  blending
  Exploration         19,513        13,626                47,331          48,737
  Exploration –
  non-cash stock      983           1,126                 3,013           3,048
  compensation
  (b)
  Abandonment and
  impairment of       11,692        40,118                46,066          104,048
  unproved
  properties
  General and         33,564        33,333                104,525         93,953
  administrative
  General and
  administrative
  – non-cash          11,031        10,057
  stock
  compensation                                            34,600          30,755
  (b)
  General and
  administrative      324           1,107                 91,589          2,523
  – lawsuit
  settlements
  General and
  administrative      -             -                     250             -
  – bad debt
  expense
  Deferred
  compensation        (2,225  )     20,052                33,257          21,555
  plan (e)
  Interest            44,321        43,997                131,602         124,090
  expense
  Loss on early
  extinguishment      -             -                     12,280          -
  of debt
  Depletion,
  depreciation        130,343       123,059               365,439         332,012
  and
  amortization
  Impairment of
  proved             7,012       1,281               7,753         1,281     
  properties and
  other assets
  Total costs and    410,994     382,690    7   %    1,284,902     1,057,536    21  %
  expenses
                                                                                        
Income (loss)
from operations       31,044        (82,910 )   137 %     149,731         (57,870   )   359 %
before income
taxes
                                                                                        
Income tax
expense
(benefit):
  Current             -             -                     -               -
  Deferred           11,866      (29,074 )            62,180        (17,910   )
                     11,866      (29,074 )            62,180        (17,910   )
                                                                                        
Net income (loss)   $ 19,178     $ (53,836 )   136 %   $ 87,551       $ (39,960   )   319 %
                                                                                        
Net Income (Loss)
Per Common Share:
                                                                                        
  Basic             $ 0.12       $ (0.34   )           $ 0.54         $ (0.25     )
  Diluted           $ 0.12       $ (0.34   )           $ 0.53         $ (0.25     )
                                                                                        
Weighted average
common shares
outstanding, as
reported:
  Basic               160,500       159,563     1   %     160,398         159,297       1   %
  Diluted             161,374       159,563     1   %     161,321         159,297       1   %
                                                                                            

(a) See separate natural gas, NGLs and oil sales information table.

(b) Costs associated with stock compensation and restricted stock
amortization, which have been reflected in the categories associated with the
direct personnel costs, which are combined with the cash costs in the 10-Q.

(c) Included in Derivative fair value income in the 10-Q.

(d) Included in Brokered natural gas, marketing and other revenues in the
10-Q.

(e) Reflects the change in market value of the vested Company stock held in
the deferred compensation plan.

                                               
RANGE RESOURCES CORPORATION
                                                 
BALANCE SHEETS
(In thousands)                                   September 30,  December 31,
                                                  2013          2012      
                                                 (Unaudited)     (Audited)
Assets
Current assets                                   $ 164,560       $ 190,062
Unrealized derivatives                             55,993          137,552
Deferred tax asset                                 2,179           -
Natural gas and oil properties, successful         6,507,304       6,096,184
efforts method
Transportation and field assets                    34,914          41,567
Other assets                                      265,680       263,370   
                                                 $ 7,030,630    $ 6,728,735 
                                                                 
Liabilities and Stockholders’ Equity
Current liabilities                              $ 443,246       $ 448,202
Asset retirement obligations                       2,366           2,470
Unrealized derivatives                             7,971           4,471
                                                                 
Bank debt                                          427,000         739,000
Subordinated notes                                2,640,170     2,139,185 
                                                  3,067,170     2,878,185 
                                                                 
Deferred tax liability                             759,556         698,302
Unrealized derivatives                             103             3,463
Deferred compensation liability                    207,404         187,604
Asset retirement obligation & other               151,813       148,646   
liabilities
                                                   1,118,876       1,038,015
                                                                 
Common stock and retained earnings                 2,375,019       2,278,243
Common stock held in treasury                      (3,751    )     (4,760    )
Accumulated other comprehensive income            19,733        83,909    
Total stockholders’ equity                        2,391,001     2,357,392 
                                                 $ 7,030,630    $ 6,728,735 

                                                                            
RECONCILIATION OF TOTAL REVENUES AND
OTHER INCOME TO TOTAL REVENUE EXCLUDING
CERTAIN ITEMS, a non-GAAP measure
(Unaudited, in    Three Months Ended September 30,   Nine Months Ended September 30,
thousands)
                   2013        2012      %      2013          2012      %  
                                                                                   
Total revenues
and other         $ 442,038     $ 299,780     47 %   $ 1,434,633     $ 999,666     44 %
income, as
reported
Adjustment for
certain special
items:
Change in fair
value of
derivatives
that did not
qualify or were     34,219        53,646               (28,350   )     (30,075 )

not designated
for hedge
accounting
Hedge
ineffectiveness     (815    )     4,707                2,485           5,061
(gain) loss
(Gain) loss on      (6,008  )     (949    )            (89,129   )     12,704
sale of assets
Brokered
natural gas -      (36,278 )    -                  (40,216   )    -       
blending
Total revenue,
as adjusted,      $ 433,156    $ 357,184    21 %   $ 1,279,423    $ 987,356    30 %
non-GAAP

                                                              
RANGE RESOURCES CORPORATION
                                                                   
CASH FLOWS FROM
OPERATING
ACTIVITIES
(Unaudited, in    Three Months Ended September 30,   Nine Months Ended
thousands)                                           September 30,
                    2013            2012          2013        2012    
                                                                   
Net income        $  19,178         $  (53,836  )    $ 87,551      $ (39,960 )
(loss)
Adjustments to
reconcile net
income (loss)
to net cash
provided from
operating
activities:
(Gain) Loss
from equity
method               378               (41      )      (1,174  )     2,252
investment, net
of
distributions
Deferred income
tax expense          11,866            (29,074  )      62,180        (17,910 )
(benefit)
Depletion,
depreciation,        137,355           124,340         373,192       333,293
amortization
and impairment
Exploration dry      4,063             15              3,904         832
hole costs
Abandonment and
impairment of        11,692            40,118          46,066        104,048
unproved
properties
Mark-to-market
on natural gas,
NGLs and oil         34,219            53,645          (28,350 )     (30,076 )
derivatives not
designated as
hedges
Unrealized
derivatives          (815     )        4,707           2,485         5,061
(gain) loss
Allowance for        -                 -               250           -
bad debts
Amortization of
deferred
issuance costs,
loss on              3,073             2,077           19,735        5,970
extinguishment
of debt and
other
Deferred and
stock-based          10,862            32,232          74,187        58,573
compensation
Gain (loss) on       (6,008   )        (949     )      (89,129 )     12,704
sale of assets
                                                                   
Changes in
working
capital:
Accounts             7,491             (21,090  )      (6,506  )     (9,479  )
receivable
Inventory and        1,714             (2,570   )      3,259         (5,394  )
other
Accounts             (18,853  )        32,996          (29,234 )     11,074
payable
Accrued
liabilities and     6,762           (4,393   )     (15,550 )    30,135  
other
Net changes in      (2,886   )       4,943         (48,031 )    26,336  
working capital
Net cash
provided from     $  222,977       $  178,177      $ 502,866    $ 461,123 
operating
activities
                                                                   
RECONCILIATION
OF NET CASH
PROVIDED FROM
OPERATING
ACTIVITIES, AS
REPORTED, TO
CASH FLOW FROM
OPERATIONS
BEFORE
CHANGES IN
WORKING
CAPITAL, a
non-GAAP
measure
(Unaudited, in    Three Months Ended September 30,   Nine Months Ended
thousands)                                           September 30,
                    2013            2012          2013        2012    
                                                                   
Net cash
provided from
operating         $  222,977        $  178,177       $ 502,866     $ 461,123
activities, as
reported
Net changes in       2,886             (4,943   )      48,031        (26,336 )
working capital
Exploration          15,450            13,611          43,427        47,905
Lawsuit              324               1,107           91,589        2,523
settlements
Equity method
investment
distribution /       (646     )        1,053           632           (2,057  )
intercompany
elimination
Loss on gas          3,720             -               3,799         -
blending
Prior year
Pennsylvania         -                 -               -             24,707
impact fee
Non-cash
compensation        (619     )       146           (578    )    3       
adjustment
Cash flow from
operation
before changes
in working        $  244,092       $  189,151      $ 689,766    $ 507,868 
capital, a
non-GAAP
measure
                                                                   
                                                                   
                                                                   
ADJUSTED
WEIGHTED
AVERAGE SHARES
OUTSTANDING
(Unaudited, in    Three Months Ended September 30,   Nine Months Ended
thousands)                                           September 30,
                    2013            2012          2013        2012    
Basic:
Weighted
average shares       163,407           162,527         163,155       162,198
outstanding
Stock held by
deferred            (2,907   )       (2,964   )     (2,757  )    (2,901  )
compensation
plan
Total reported      160,500         159,563       160,398     159,297 
                                                                   
Dilutive:
Weighted
average shares       163,407           162,527         163,155       162,198
outstanding
Dilutive stock
options under       (2,033   )       (2,964   )     (1,834  )    (2,901  )
treasury method
Total reported      161,374         159,563       161,321     159,297 

                                                                                         
RANGE RESOURCES CORPORATION
                                                                                                
RECONCILIATION OF NATURAL GAS, NGLs AND OIL
SALES AND DERIVATIVE FAIR VALUE INCOME (LOSS)
TO CALCULATED CASH REALIZED NATURAL GAS,
NGLs AND OIL PRICES WITH AND WITHOUT THIRD
PARTY TRANSPORTATION, GATHERING AND
COMPRESSION FEES
non-GAAP measures
(Unaudited, in
thousands,        Three Months Ended September 30,          Nine Months Ended September 30,
except per unit
data)
                   2013           2012         %       2013            2012          %   
Natural gas,
NGLs and Oil
Sales
components:
Natural gas       $ 233,019        $ 159,525                $ 718,176         $ 399,006
sales
NGLs sales          77,317           56,826                   211,475           189,604
Oil sales           93,473           59,221                   243,057           166,718
                                                                                                
Cash-settled
hedges
(effective):
Natural Gas         25,870           62,150                   90,693            198,675
Crude Oil          1,535          (682       )            3,730           (997        )
Total Oil and
Gas Sales, as     $ 431,214       $ 337,040       28  %   $ 1,267,131      $ 953,006        33  %
reported
                                                                                                
Derivative Fair
Value Income
(Loss)
components:
Realized gain
(loss) on
settlement:
Natural Gas       $ 4,961          $ 988                    $ (18,358     )   $ 3,451
NGLs                (3,907     )     14,682                   (1,759      )     20,442
Crude Oil           (8,005     )     1,955                    (8,218      )     (1,899      )
Change in fair
value of
derivatives
that did not
qualify or were     (34,219    )     (53,646    )             28,350            30,075
not designated
for hedge
accounting


Unrealized
hedge              815            (4,707     )            (2,485      )    (5,061      )
ineffectiveness
Total
Derivative Fair
Value Income      $ (40,355    )   $ (40,728    )           $ (2,470      )   $ 47,008      
(Loss), as
reported
                                                                                                
Transportation,
Gathering and
Compression
components:
Natural Gas       $ 57,576         $ 48,737                 $ 179,571         $ 129,411
NGLs               3,382          2,863                  9,851           7,753       
Total
transportation,
gathering and     $ 60,958        $ 51,600                $ 189,422        $ 137,164     
compression, as
reported
                                                                                                
Natural gas,
NGL and Oil
sales,
including
cash-settled
derivatives
(c):
Natural Gas       $ 263,850        $ 222,663                $ 790,511         $ 601,132
Sales
NGL Sales           73,410           71,508                   209,716           210,046
Oil Sales          87,003         60,494                 238,569         163,822     
Total             $ 424,263       $ 354,665       20  %   $ 1,238,796      $ 975,000        27  %
                                                                                                
Production of
Oil and Gas
during the
periods (a):
Natural Gas         68,024,813       57,347,638     19  %     194,975,047       156,274,072     25  %
(mcf)
NGL (bbl)           2,362,340        1,843,667      28  %     6,367,253         4,975,086       28  %
Oil (bbl)           1,018,013        712,858        43  %     2,795,192         1,943,961       44  %
Gas equivalent      88,306,931       72,686,788     21  %     249,979,717       197,788,354     26  %
(mcfe) (b)
                                                                                                
Production of
Oil and Gas –
average per day
(a):
Natural Gas         739,400          623,344        19  %     714,194           570,343         25  %
(mcf)
NGL (bbl)           25,678           20,040         28  %     23,323            18,157          28  %
Oil (bbl)           11,065           7,748          43  %     10,239            7,095           44  %
Gas equivalent      959,858          790,074        21  %     915,567           721,855         27  %
(mcfe) (b)
                                                                                                
Average prices,
including cash
settled hedges
that qualify
for hedge
accounting
before third
party
transportation
costs: (c)
Natural Gas       $ 3.81           $ 3.87           -2  %   $ 4.15            $ 3.82            8   %
(mcf)
NGL (bbl)         $ 32.73          $ 30.82          6   %   $ 33.21           $ 38.11           -13 %
Oil (bbl)         $ 93.33          $ 82.12          14  %   $ 88.29           $ 85.25           4   %
Gas equivalent    $ 4.88           $ 4.64           5   %   $ 5.07            $ 4.82            5   %
(mcfe) (b)
                                                                                                
Average prices,
including
cash-settled
hedges and
derivatives
before third
party
transportation
costs: (c)
Natural Gas       $ 3.88           $ 3.88           0   %   $ 4.05            $ 3.85            5   %
(mcf)
NGL (bbl)         $ 31.08          $ 38.79          -20 %   $ 32.94           $ 42.22           -22 %
Oil (bbl)         $ 85.46          $ 84.86          1   %   $ 85.35           $ 84.27           1   %
Gas equivalent    $ 4.80           $ 4.88           -2  %   $ 4.96            $ 4.93            1   %
(mcfe) (b)
                                                                                                
Average prices,
including
cash-settled
hedges and
derivatives
(d):
                                                                                                
Natural Gas       $ 3.03           $ 3.03           0   %   $ 3.13            $ 3.02            4   %
(mcf)
NGL (bbl)         $ 29.64          $ 37.23          -20 %   $ 31.39           $ 40.66           -23 %
Oil (bbl)         $ 85.46          $ 84.86          1   %   $ 85.35           $ 84.27           1   %
Gas equivalent    $ 4.11           $ 4.17           -1  %   $ 4.20            $ 4.24            -1  %
(mcfe) (b)
                                                                                                
Transportation,
gathering and
compression       $ 0.69           $ 0.71           -3  %   $ 0.76            $ 0.69            9   %
expense per
mcfe
                                                                                                    

(a) Represents volumes sold regardless of when produced.

(b) Oil and NGLs are converted at the rate of one barrel equals six mcfe based
upon the approximate relative energy content of oil to natural gas, which is
not necessarily indicative of the relationship of oil and natural gas prices.

(c) Excluding third party transportation, gathering and compression costs.

(d) Net of transportation, gathering and compression costs.

                                                                           
RANGE RESOURCES CORPORATION
                                                                                  
RECONCILIATION OF INCOME (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES AS REPORTED TO
INCOME FROM OPERATIONS BEFORE INCOME TAXES
EXCLUDING CERTAIN ITEMS, a non-GAAP measure
(Unaudited, in
thousands,        Three Months Ended September 30,    Nine Months Ended September 30,
except per
share data)
                   2013        2012      %       2013        2012      %   
                                                                                  
Income (loss)
from operations
before income     $ 31,044      $ (82,910 )   137 %   $ 149,731     $ (57,870 )   359 %
taxes, as
reported
Adjustment for
certain special
items:
Gain (loss) on      (6,008  )     (949    )             (89,129 )     12,704
sale of assets
Change in fair
value of
derivatives
that did not
qualify or were     34,219        53,646                (28,350 )     (30,075 )
not designated
for hedge
accounting
(gain) loss
Unrealized
hedge               (815    )     4,707                 2,485         5,061
ineffectiveness
(gain) loss
Abandonment and
impairment of       11,692        40,118                46,066        104,048
unproved
properties
Loss on gas
blending –
brokered            3,720         -                     3,799         -
natural gas and
marketing
Loss on early
extinguishment      -             -                     12,280        -
of debt
Prior year
Pennsylvania        -             -                     -             24,707
impact fee
Impairment of
proved property     7,012         1,281                 7,753         1,281
and other
assets
Lawsuit             324           1,107                 91,589        2,523
settlements
Brokered
natural gas and
marketing – non     531           452                   1,310         1,313
cash
stock-based
compensation
Direct
operating –
non-cash            699           598                   2,056         1,647
stock-based
compensation
Exploration –
non-cash            983           1,126                 3,013         3,048
stock-based
compensation
General &
administrative
– non-cash          11,031        10,057                34,600        30,755
stock-based
compensation
Deferred
compensation       (2,225  )    20,052              33,257      21,555  
plan – non-cash
adjustment
                                                                                  
Income from
operations
before income       92,207        49,285      87  %     270,460       120,697     124 %
taxes, as
adjusted
                                                                                  
Income tax
expense, as
adjusted
Current             -             -                     -             -
Deferred           35,244      17,287              105,542     46,199  
Net income
excluding
certain items,    $ 56,963     $ 31,998     78  %   $ 164,918    $ 74,498     121 %
a non-GAAP
measure
                                                                                  
Non-GAAP income
per common
share
Basic             $ 0.35       $ 0.20       75  %   $ 1.03       $ 0.47       119 %
Diluted           $ 0.35       $ 0.20       75  %   $ 1.02       $ 0.47       117 %
                                                                                  
Non-GAAP
diluted shares     161,374     160,222             161,321     160,130 
outstanding, if
dilutive

                                           
HEDGING POSITION AS OF OCTOBER 29, 2013 –
(Unaudited)
                                                
                                 Daily Volume   Hedge Price
    Gas (Mmbtu)
    4Q 2013 Swaps                293,370        $3.82
    4Q 2013 Collars              280,000        $4.59 - $5.05
                                                
    2014 Swaps                   50,000         $4.12
    2014 Collars                 447,500        $3.84 - $4.48
                                                
    2015 Swaps                   67,500         $4.16
    2015 Collars                 145,000        $4.07 - $4.56
                                                
    Oil (Bbls)
    4Q 2013 Swaps                6,825          $96.79
    4Q 2013 Collars              3,000          $90.60 - $100.00
                                                
    2014 Swaps                   7,500          $94.33
    2014 Collars                 2,000          $85.55 - $100.00
                                                
    2015 Swaps                   3,000          $90.13
                                                
    C5 Natural Gasoline (Bbls)
    4Q 2013 Swaps                6,500          $2.134
                                                
    C4 Normal Butane (Bbls)
    4Q 2013 Swaps                2,000          $1.320
                                                
    2014 Swaps                   3,000          $1.328
                                                
    C3 Propane (Bbls)
    4Q 2013 Swaps                11,000         $0.945
                                                
    2014 Swaps                   10,000         $0.989

     NOTE: SEE WEBSITE FOR OTHER SUPPLEMENTAL INFORMATION FOR THE PERIODS

Contact:

Range Resources Corporation
Investor Contacts:
Rodney Waller, 817-869-4258
Senior Vice President
or
David Amend, 817-869-4266
Investor Relations Manager
or
Laith Sando, 817-869-4267
Research Manager
or
Michael Freeman, 817-869-4264
Financial Analyst
or
Media Contact:
Matt Pitzarella, 724-873-3224
Director of Corporate Communications
www.rangeresources.com
 
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